A novel sedimentologically controlled accumulation pattern for marine shale gas: insights from the “source-reservoir-seal” configurations of lower Carboniferous shale in the Yaziluo rift trough, Southern China

Substantial shale gas discoveries in the rift troughs of southern China have demonstrated significant resource potential in marine shale formations. However, the complex vertical lithofacies architecture, resulting from diverse sedimentary environments and characterized by recurrent alternation of mudstone and argillaceous limestone layers, presents challenges in understanding shale associations characteristics across different sedimentary facies and their associated gas accumulation mechanisms. This study focuses on the Lower Carboniferous shale within the Yaziluo Rift Trough, employing an integrated analytical approach incorporating geochemical characterization, X-ray diffraction, field emission scanning electron microscopy (FE-SEM), and high-pressure methane isothermal adsorption experiments to evaluate various shale associations. Key findings reveal that lower slope facies shale association constitute optimal exploration targets, developing an integrated “source-reservoir-seal” configuration that enhances gas accumulation and retention. Its high-quality reservoirs emerge at lithological transitions zones where interconnected inorganic pore networks and microfracture systems facilitate efficient gas migration from source rocks, resulting in elevated gas accumulation. The upper slope facies shale association exhibit spatially heterogeneous configurations dominated by multiple sets of argillaceous limestone interbeds, forming vertically compartmentalized systems conducive to free gas migration and multi-point accumulation. In contrast, basin facies shale association demonstrate constrained gas retention capacity due to clay-dominated mineralogy and absence of argillaceous limestone interlayers. This study emphasizes the critical role of lithofacies heterogeneity and integrated “source-reservoir-seal” configurations in evaluation of shale gas accumulation, which provides a new paradigm for the exploration of rift trough shale gas.

1 Introduction

The commercial shale gas flow achieved by the JY1 well in the Sichuan Basin of China (20.4 × 10⁴ m³/d) has established the Lower Silurian Longmaxi Formation, deposited in a deep-water continental shelf setting, as a key exploration target (Shu et al., 2020; Wang et al., 2022). Previous research has primarily focused on integrated source-reservoir systems in deep-water shelf shale within cratonic graben basins (Zhao et al., 2016; Xi et al., 2022), while studies on shale systems in rift trough environments remain limited. Even if such studies exist, they mostly focus on revealing hydrocarbon generation potential from a sedimentary facies perspective (Han et al., 2020; Yuan et al., 2020), without comprehensively addressing shale gas enrichment mechanisms or establishing enrichment patterns. However, recent significant shale gas discoveries in southern China’s rift trough, including the Yaziluo, Kaijiang-Liangping, Wanjiang, and western Hubei rift troughs (Ma et al., 2019; Wang et al., 2020), have highlighted their critical importance as marine shale gas exploration targets.

For instance, the EYY-1 well in the western Hubei Rift Trough yielded an industrial gas flow of 7.83 × 10⁴ m³/d from the Cambrian Niutitang Formation, and the HY-1 well also achieved an industrial gas flow (8.9 × 10⁴ m³/d) from the Permian Wujiaoping Formation (Zhai et al., 2020; Hu et al., 2023). In the Kaijiang-Liangping Rift Trough, the DY-1 well produced a high-yield industrial gas flow of 32.06 × 10⁴ m³/d from the Permian Wujiaoping Formation (Yang et al., 2023; Yang et al., 2025a), while the LY-1 well obtained 42.66 m³/d from the Permian Dalong Formation (Jin et al., 2025). Additionally, the Permian Gufeng Formation and Dalong Formation in the Wanjiang Rift Trough have also shown promising shale gas discoveries through drilling well (Zhai et al., 2020; Jin et al., 2025). These significant shale gas discoveries have proved that black shale deposits in rift troughs represent vital targets for enhancing China’s shale gas reserves and resources.

These V-shaped rift troughs, characterized by narrow geometries and bounded by high-angle syndepositional faults formed through crustal extension (Ma et al., 2006), exhibit distinctive “slope-basin” depositional architectures. Developed under dynamic hydrodynamic conditions with multiple sediment sources (Ding et al., 2019; Wu et al., 2020), they feature vertically heterogeneous lithofacies distributions. Recurrent lithological alternations under varying paleoclimatic, paleoceanographic, and paleontological conditions forms basin and slope facies shale associations with markedly different gas-bearing capacities (Chen et al., 2024; Zhai et al., 2025). Deep-water shelf facies shale in cratonic graben basin have been confirmed as primary sweet spot intervals (Shu et al., 2020; Xi et al., 2022). However, the basin facies shale associations within rift trough, despite revealing similar geological characteristics, including continuously developed thick-layer, high TOC and silica content (Wang et al., 2017a; Zhao et al., 2017a), have yielded suboptimal exploration outcomes. Conversely, slope facies shale associations, with relatively lower TOC content, higher carbonate mineral content, and extensive microfracture development, generally exhibit superior gas-bearing capacity. Obviously, this discrepancy indicates that direct application of cratonic graben basin concepts is inadequate for addressing shale gas accumulation in rift trough settings. The insufficient understanding of the intricate interplay between complex sedimentological heterogeneity and gas accumulation mechanisms significantly impedes exploration efficiency.

Historically, shale formations in rift troughs were not prioritized for exploration due to rapid facies variations, limited continuous thickness, abundant limestone interbeds, and complex lithofacies architectures. Elevated carbonate mineral contents and well-developed inorganic pore-fracture systems further complicated conventional shale gas exploration strategies. However, advances in integrated geological-engineering methodologies and hydraulic fracturing technologies, particularly for acidic shale reservoirs, have shifted exploration focus toward slope facies shale associations in rift troughs over traditional deep-water shelf facies. Zhang et al. (2023) highlighted that while slope facies shale within rift troughs exhibit relatively subdued hydrocarbon generation and preservation conditions compared to other settings, their natural fracture networks and pore systems significantly enhance gas storage capacity and reservoir permeability. They further emphasize that structural deformation and fracture development synergistically govern shale gas enrichment in these settings (Zhang et al., 2021; Zhang et al., 2023). Based on these findings, Yang et al. (2025b) demonstrated that even in the presence of thin organic-rich shale intervals and high carbonate mineral contents, targeted multistage hydraulic fracturing techniques can achieve commercially viable production rates and long-term reservoir stability. Jin et al. (2025) proposed that ongoing technological advancements, specifically in multi-layered reservoir stimulation and understanding of mechanical stratigraphy-driven fracture propagation, are poised to unlock previously untapped shale gas resources within rift trough. This underscores the growing importance of slope facies shale associations in future exploration strategies. However, critical challenges still persist, including marked gas content disparities among shale facies associations and the poorly understood interplay between sedimentological heterogeneity and gas migration-accumulation mechanisms. These unresolved issues hinder the identification of high-potential sweet spots and breakthroughs in rift troughs of southern China, necessitating systematic investigations into how shale facies architecture influences reservoir quality and gas accumulation.

Therefore, this study takes the Lower Carboniferous shale of the Yaziluo Rift Trough as a case study, conducting a comparative analysis of typical shale association across sedimentary facies to achieve three primary objectives. (1) Characterize typical shale associations in distinct sedimentary environments; (2) quantify gas contents by calculating theoretical gas contents and free/adsorbed gas ratios for each shale association type; (3) establish sedimentary facies-controlled gas accumulation pattern from the perspective of “source-reservoir-seal” configurations. This systematic approach not only provides new insights for shale gas exploration in the rift troughs, but also comprehensively characterizes key controls on gas accumulation heterogeneity.

2 Geological setting

The Early Devonian expansion of the Paleo-Tethys Ocean induced NE-SW oriented extensional tectonics, forming an intracontinental rift system, notably the Yaziluo Rift Trough (Wang et al., 2006; Wang et al., 2013; Han et al., 2020). The Lower Carboniferous shale within the Yaziluo Rift Trough exhibits significant thickness variations, ranging from 34 m to 1566 m, with NW-SE oriented depocenters dominating the central regions (Wang et al., 2006). The Lower Carboniferous succession in the Yaziluo Rift Trough comprises four principal sedimentary facies: basin, slope, platform, and littoral facies (Figure 1A) (Wang et al., 2006; Tian and Yang, 2016).

Figure 1

Figure 1. (A) Distribution of the Yaziluo Rift Trough during the late Carboniferous period, showing the sampling wells (well A, well B and well C); (B) Sequence stratigraphic framework according to (Geology and Mineral Resources Bureau of Guangxi Zhuang Autonomous Region, 1985); (C) Sedimentary model of the Lower Carboniferous Formation. (modified from (Chen et al., 2024)).

The basin facies, spanning from the Luzhai region (southeastern margin) to the Liupanshui area (northwestern margin), primarily consists of calcareous mudstone, siliceous mudstone, and silicalite (Figure 1B). The slope facies deposits, situated within the transitional belt between platform and basin facies domains, are lithologically characterized by interbedded mudstones, calcareous mudstones, and argillaceous limestones. Furthermore, the slope facies can be subdivided into upper slope and lower slope facies. The lower slope facies, situated at the rift trough’s edge between the platform and basin, represents a narrow sub-deepwater low-energy facies belt. In contrast, the upper slope facies, being closer to the platform, comprises primarily dark gray argillaceous mudstone, argillaceous siltstone, and interbedded gray mudstone. Paleobathymetric reconstruction along the Liupanshui-Ziyun- Luzhai transect reveals a progressive shallowing trend from the rift axis regions toward the flanks regions (Wang et al., 2013; Han et al., 2020). This trend is manifested by systematic lateral facies transitions, progressing from the basin facies in the central trough, through the slope facies in the transitional belt, to the platform facies on the marginal highs, and finally culminating in the littoral facies along the paleo-coastal zones (Figure 1C). This sequence of facies transitions is a direct manifestation of the paleo-seawater depth, which was influenced by the paleo-oceanographic inflow axis during marine transgression events (Chen et al., 2024).

To further investigate the differential accumulation pattern of lower Carboniferous shale gas in Yaziluo Rift Trough, three exploration wells (Wells A-C) were strategically drilled perpendicular to the paleobathymetric gradient (Figure 1A). Well A (Luzhai region) targeted basin facies in deep marine settings, Well B (Rongshui region) sampled lower slope facies at the slope-basin interface, and Well C (Liupanshui region) accessed upper slope facies near platform margins.

The Lower Carboniferous shale within Yaziluo Rift Trough developed in a dynamic depositional environment with fluctuating seawater levels and diverse sediment sources. Syndepositional faults strongly control sedimentary facies distribution and shale association heterogeneity across basin, lower slope, and upper slope facies (Huang et al., 2013; Mei et al., 2013; Yuan et al., 2020). The stratigraphic sequence exhibits frequent alternations between shale and argillaceous limestone, presenting a distinctive “sandwich-type” configuration (Mei et al., 2007; Chen et al., 2021). This lithological alternation leads to vertical variations in lithofacies positioning and differential spatial stacking relationships, ultimately forming distinct vertical shale association patterns.

A classification scheme for typical shale associations was established based on continuous shale thickness, lithofacies types, and interbedding relationships. Using shale-to-argillaceous limestone ratios as key criteria, three thresholds (90%, 60%, and 40%) define representative types of shale association corresponding to specific sedimentary facies: (1) shale association of basin facies (shale >90%); (2) shale association of lower slope facies (60 < shale <90%); (3) shale association of upper slope facies (40 < shale <60%). This classification system effectively reflects the vertical lithofacies variations and provides a foundational framework for subsequent investigations into differential accumulation patterns of shale gas (Figure 2).

Figure 2

Figure 2. The classification scheme for typical shale association in different sedimentary facies.

3 Materials and methods

3.1 Samples

A total of 107 shale core samples were systematically collected from the Lower Carboniferous strata in the Yaziluo Rift Trough, South China, comprising 28 samples from Well A, 41 samples from Well B, and 38 samples from Well C. All samples underwent standardized preparation involving precision cutting and polishing for subsequent geochemical and petrological analyses. A total of 73 samples were subjected to Total Organic Carbon (TOC), while 47 samples were selected for mineralogical characterization through X-ray diffraction (XRD). To investigate the microscopic characterization of shale reservoir, 12 representative samples were selected for detailed pore structure analysis through field emission scanning electron microscopy (FE-SEM). Gas content evaluation was conducted on 29 samples through field desorption measurements following standardized protocols, complemented by theoretical gas content analysis through high-pressure methane isothermal adsorption experiments on 14 core samples.

3.2 Analytical methods

3.2.1 Geochemical and mineral compositions characteristics

The TOC content was performed using ta Leco-CS230 Carbon/Sulfur Analyzer (±5% accuracy) following the Chinese National Standard (GB/T 19,145-2003). Sample preparation involved pulverization to <200 mesh (75–90 μm). This was followed by hydrochloric acid treatment at 60 °C for 4 h to ensure complete removal of inorganic carbon, with periodic agitation to enhance reaction efficiency. Subsequent distilled water rinsing with oven-drying at 60 °C–80 °C. Mineralogical analysis was conducted using a Rigaku Smart Lab-9 XRD system following the Chinese Oil and Gas Industry Standard (SY/T) 5163-2010, with samples ground to <40 μm and pre-dried at 40 °C for 48 h.3.2.2 Field emission-scanning electron microscopy (FE-SEM).

Standardized cylindrical plugs were prepared through precision sectioning, followed by sequential surface processing: mechanical polishing with diamond abrasives and advanced argon ion beam milling to create ultra-smooth observation surfaces. High-resolution microstructural characterization was performed using a ZEISS Sigma 300 FE-SEM system, achieving nanoscale resolution of pore features.

3.2.2 Measured gas content

Field measurements utilized brine-saturated containment vessels maintained at reservoir temperature for ≥72 h desorption monitoring. Subsequent laboratory analysis quantified residual gas content, with lost gas estimation through linear regression modeling (Ma et al., 2015). Isothermal adsorption experiments employed ultra-high purity methane (99.99%) under reservoir temperature conditions, measuring high-pressure CH₄ adsorption capacities on desiccated shale samples.

3.2.3 Theoretical adsorbed gas content

The Langmuir isothermal adsorption model, originally proposed by Langmuir (1918) for gas adsorption equilibrium analysis, has been widely adopted for quantifying adsorbed gas content in shale reservoirs. Subsequent studies (Zhang et al., 2017; Zhao et al., 2017b) refined the parameters of the Langmuir monolayer adsorption equation to better characterize shale methane adsorption isotherms. The fundamental equation is expressed as:

$V_q=\frac{{\mathrm{V}}_L\times \mathrm{P}}{\mathrm{P}+{\mathrm{P}}_L}(6.1)$

where $V_q$ represents the adsorbed gas content (m³/t), P is the formation pressure (MPa), ${\mathrm{V}}_L$ denotes the Langmuir volume (m³/t), and ${\mathrm{P}}_L$ is the Langmuir pressure (MPa).

Equation 6.1 allows the calculation of adsorbed gas content $V_q$ under reservoir temperature and pressure conditions. Formation pressure (P) and temperature (T) vary with depth according to:

$\mathrm{P}={\mathrm{P}}_C\times {\mathrm{\rho }}_w\times \mathrm{g}\times \mathrm{H}\times {10}^{-6}(6.2)$

$\mathrm{T}={\mathrm{T}}_0+{\mathrm{T}}_G\times \mathrm{H}(6.3)$

where, $P_c$ is the formation pressure coefficient (dimensionless), ${\mathrm{\rho }}_w$ is water density (g/cm³), g is gravitational acceleration (N/kg), H is burial depth (m), T is formation temperature (°C), T₀ is surface temperature (°C), and ${\mathrm{T}}_G$ is the geothermal gradient (°C/m).

By incorporating region-specific values of $P_c$ and $T_0$ for the Yaziluo Rift Trough, Equations 6.2,6.3, enable the determination of formation pressure (P) and temperature (T) at varying burial depths for drill core samples.

In addition, shale gas content is governed by multiple factors, necessitating parameter calibration to account for organic carbon content (TOC) and variations in formation temperature across samples (Lewi et al., 2004). Temperature-dependent corrections are applied using the following equations:

${\mathrm{V}}_{lt}={10}^{\left(-\mathrm{C}3\times \mathrm{T}+\mathrm{C}4\right)}(6.4)$

${\mathrm{P}}_{lt}={10}^{\left(\mathrm{C}7\times \mathrm{T}+\mathrm{C}8\right)}(6.5)$

$\mathrm{C}4=\log {\mathrm{V}}_L+\left(\mathrm{C}3\times {\mathrm{T}}_i\right)(6.6)$

$\mathrm{C}8=\log {\mathrm{P}}_L+\left(-\mathrm{C}7\times {\mathrm{T}}_i\right)(6.7)$

where $V_{lt}$ is the temperature-corrected Langmuir volume (${\mathrm{V}}_L$ , m³/t), $P_{lt}$ is the temperature-corrected Langmuir pressure ($P_L$ , MPa), T_i is the standard temperature (°C) set during isothermal adsorption experiments, T is the formation temperature (°C), and the coefficients C3 and C7 are 0.0027 and 0.005, respectively.

TOC-based correction is integrated into the model:

${\mathrm{V}}_{lc}={\mathrm{V}}_{lt}\times \frac{\text{TOC}}{{\text{TOC}}_{\mathit{lg}}}(6.8)$

where $V_{lc}$ is the Langmuir volume (m³/t) calibrated for both formation temperature (T) and TOC, and ${TOC}_{\mathit{lg}}$ represents the TOC (%) derived from well-logging data interpretation.

The refined Langmuir model for adsorbed gas content, incorporating temperature and TOC corrections, is expressed as:

$V_{Lt}=\frac{{\mathrm{V}}_{lc}\times \mathrm{P}}{\mathrm{P}+{\mathrm{P}}_{lt}}(6.9)$

where $V_{Lt}$ is the adsorbed gas content (m³/t) and P is the reservoir pressure (MPa).

To account for the 10% reduction in methane adsorption capacity due to moisture content (Zhang et al., 2017), the final equation becomes:

$V_{ads}=\frac{{\mathrm{V}}_{lc}\times \mathrm{P}}{\mathrm{P}+{\mathrm{P}}_{lt}}\times 90\%(6.10)$

where $V_{ads}$ denotes the fully calibrated adsorbed gas content (m³/t).

3.2.4 Theoretical free gas content

Ambrose et al. (2011) proposed that adsorbed-phase gas occupies free gas pore space, necessitating volumetric correction (Tian and Yang, 2016; Guo et al., 2023). The maximum pore volume available for free gas equals the total shale pore volume minus the adsorbed-phase pore volume, as expressed by:

$V_f=V_p-V_a(6.11)$

where $V_f$ is the maximum free-phase pore volume under reservoir conditions (cm³/g), $V_p$ denotes the total shale pore volume (cm³/g), and $V_a$ represents the adsorbed-phase pore volume (cm³/g).

Accoding to the free gas calculation model proposed by Yang and Guo, 2022, the adsorbed-phase pore volume is calculated as:

$V_a=V_s·\frac{{\rho }_{std}}{{\rho }_{ads}}(6.12)$

where $V_s$ is the standard-state adsorbed methane volume (cm³/g), ${\rho }_{std}$ is the methane density at standard conditions (0.716 × 10⁻³ g/cm³), and ${\rho }_{ads}$ is the adsorbed methane density under subsurface conditions (g/cm³).

The standard-state free methane volume is expressed as:

$V_{free}=V_f·\frac{{\rho }_N}{{\rho }_{std}}·S_g(6.13)$

where $V_{free}$ is the maximum free gas volume under standard conditions (cm³/g), and ${\rho }_N$ is the methane density under reservoir conditions.

Subsequent studies (Shi et al., 2015; Zhang et al., 2017) have proposed a TOC-based method for determining shale water saturation, where gas saturation (S_g) and water saturation (S_w) are interconvertible through the following expressions:

$S_w=\left(\sqrt[\mathrm{n}]{{TOC}_b/TOC}\right)·100\%,S_g=\left(1-S_w\right)\times 100\%(6.14)$

where S_w represents water saturation (%), S_g denotes gas saturation (%), TOC_b is the total organic carbon content of non-reservoir intervals at equivalent burial depth, TOC is the measured TOC value of the shale reservoir, and n is the gas saturation index, typically ranging from 2 to 3 in shale reservoirs.

By substituting Equation 6.11 into Equation 6.12 and combining the result with Equation 6.13 and Equation 6.14, the free gas volume under shale formation conditions can be derived as:

$V_{free}=\left(V_p-V_s·\frac{{\rho }_{std}}{{\rho }_{ads}}\right)·\frac{{\rho }_{NIST}}{{\rho }_{std}}·S_g(6.15)$

where $V_{free}$ denotes the standard-state free gas content (m³/t).

4 Results

4.1 Classification of shale lithofacies

A tripartite classification model was used through using mineral composition as fundamental parameters, with siliceous minerals (quartz + feldspar), carbonate minerals, and clay minerals (illite, kaolinite, chlorite, and smectite) serving as the three end-members (Wang et al., 2017a). The classification scheme employs 50% mineral content as primary boundaries, categorizing shale lithofacies into four major lithofacies group. Subsequently, each group is further subdivided into four subcategories using 25%, 50%, and 75% mineral content thresholds, resulting in 16 distinct shale lithofacies types (Figure 3). The Lower Carboniferous shale in the Yaziluo Rift Trough comprises three principal lithofacies: Siliceous Shale Lithofacies (S1/S2), Mixed Shale Lithofacies (M1/M2), and Calcareous Shale Lithofacies (C2/C3), corresponding to basin facies, lower slope facies, and upper slope facies shale association respectively.

Figure 3

Figure 3. Ternary diagram showing the mineralogy of the different lithofacies within lower Carboniferous shale in in the Yaziluo Rift Trough ((modified from Wang et al., 2017b).

4.2 Petrography and organic geochemistry characteristics

4.2.1 Shale association of basin facies

This shale association includes Calcareous Siliceous Shale Lithofacies (S-1) and Mixed Siliceous Shale Lithofacies (S-2), whose organic carbon content (TOC) ranges from 1.46% to 5.70%, with an average content of 3.63% (Table 1). The S-1 lithofacies is characterized by grayish-black siliceous mudstone with calcite vein fillings (Figure 5A). Mineralogically, quartz dominates (49.2% avg.), followed by clay minerals (20.5% avg.), while calcite, dolomite, plagioclase, and pyrite collectively account for less than 10% (Figure 4). Petrographic analysis reveals an argillaceous-siliceous matrix with heterogeneous ferruginous-organic distribution. Calcite laminae exhibiting first-order white interference colors alternate with organic-rich layers (Figure 5B). The S-2 lithofacies predominantly consists of black siliceous mudstone with abundant pyrite (Figure 5C). Mineralogically, quartz constitutes the dominant component (62.4% avg.), followed by clay minerals (18.2% avg), and calcite (9.9% avg.) (Figure 4). Compared to S-1 lithofacies, it exhibits 13.2% quartz increase and 2.3% clay reduction. Petrographic analysis reveals that the matrix contains clay-quartz-pyrite assemblages with anhedral to subhedral quartz grains (0.005–0.06 mm) and lamellar pyrite structures (Figure 5D).

Table 1

Table 1. Statistics of the TOC, methane isothermal adsorption gas content, and field measured gas content in different sedimentary facies.

Figure 4

Figure 4. Mineral composition of Lower Carboniferous shale in basin facies (A)lower slope facies (B)and upper slope facies (C).

Figure 5

Figure 5. Images showing well core images and plane polarized light images in the shale samples of Well (A) Well (B) and Well (C). (A) & (C) well core images of Calcareous Siliceous Shale Lithofacies (S-1) and Mixed Siliceous Shale Lithofacies (S-2); (B) & (D) images of plane polarized light corresponding to Images (A) and (C), respectively; (E) & (G) well core images of Calcareous/Siliceous Mixed Shale Lithofacies (M-1) and Argillaceous/Siliceous Mixed Shale Lithofacies (M-2); (F) & (H) images of plane polarized light corresponding to Images (E) and (G), respectively; (I) & (K) well core images of Mixed Calcareous Shale Lithofacies (C-2) and Argillaceous-Bearing Calcareous Shale Lithofacies (C-3); (J) & (L) images of plane polarized light corresponding to Images (I) and (K), respectively.

4.2.2 Shale association of lower slope facies

This shale association contains Calcareous/Siliceous Mixed Shale Lithofacies (M-1) and Argillaceous/Siliceous Mixed Shale Lithofacies (M-2), whose TOC content ranges from 0.86% to 3.51% with a median of 1.80% (Table 1). The M-1 lithofacies features black calcareous mudstone with sporadic pyrite (Figure 5E). Mineral composition includes quartz (42.5% avg.), calcite (32.7% avg.), and clay minerals (17.3% avg.) (Figure 4). Petrographic observations reveal the matrix primarily contains angular quartz and minor feldspar fragments (0.02–0.06 mm). Subordinate calcite occurs as fine granular particles (0.02–0.05 mm) intermixed with clay minerals. Accessory pyrite manifests as black granular particles, while organic matter appears as black amorphous clots within the argillaceous matrix (Figure 5F). The M-2 lithofacies displays grayish-black calcareous mudstone with silty laminae (Figure 5G). Mineral composition is dominated by quartz (44.1% avg.) and clay minerals (30.9% avg.), followed by calcite (15.2% avg.) (Figure 4). Compared to the M-1 lithofacies, it demonstrates significantly higher clay mineral content. Petrographic analysis reveals a matrix predominantly composed of microcrystalline/cryptocrystalline clay mineral aggregates with yellowish-brown coloration. Detrital components consist mainly of monocrystalline quartz grains (0.03mm–0.1 mm), micritic calcite, and pyrite aggregates with organic clots (Figure 5H).

4.2.3 Shale association of upper slope facies

This shale association comprises Mixed Calcareous Shale Lithofacies (C-2) and Argillaceous-Bearing Calcareous Shale Lithofacies (C-3), whose TOC content ranges from 0.56% to 1.63%, with an average value of 0.99% (Table 1). The C-2 lithofacies primarily consists of grayish argillaceous limestone (Figure 5I). Mineral composition is dominated by calcite (average 38.0%) and dolomite (average 25.7%), followed by quartz (15.5%) and clay minerals (18.9%) (Figure 4). The micritic calcite matrix (<0.01 mm) contains subhedral-euhedral dolomite (0.02–0.05 mm) and organic clots (0.05–0.2 mm) (Figure 5J). The C-3 lithofacies is characterized by grayish-black calcareous mudstone, locally intercalated with siltstone (Figure 5K). Mineral composition remains carbonate-dominated, with calcite (average 27.7%) and dolomite (average 23.7%), followed by clay minerals (average 31.4%), and quartz (average 13.8%) (Figure 4). Compared to the C-2 lithofacies, it exhibits a 70% relative increase in clay mineral content. Petrographic observations demonstrate a microcrystalline clay mineral matrix containing cryptocrystalline quartz, dolomite grains (0.03–0.08 mm), and pyrite aggregates (5–20 μm) (Figure 5L).

4.3 Microscopic pore type based on FE-SEM

4.3.1 Organic pore

Basin facies shale exhibit the most developed organic pore, occupying quartz-inorganic mineral interstices and clay aggregates (Figures 6A–D). In contrast, lower slope facies shale demonstrate reduced organic pores, where organic matter pores frequently coexist with clay minerals as composite structures. Pore diameters range from several nanometers to hundreds of nanometers, displaying circular, elliptical, or irregular morphologies (Figures 6E–H). The upper slope facies shales generally exhibit poorly developed organic pore. Organic matter predominantly occurs as elongated or irregularly shaped particles interspersed among inorganic minerals, with limited intraparticle pore. Brittle minerals such as carbonates act as rigid frameworks, providing mechanical support and preservation for organic pores. Additionally, composite structures of organic matter and clay minerals are observed, with pore diameters reaching up to hundreds of nanometers (Figures 6I–L).

Figure 6

Figure 6. Images showing organic pore (red arrows) in the shale samples of Well (A) Well (B) and Well (C). (A) & (B) SEM observation images of Calcareous Siliceous Shale Lithofacies (S-1); (C) & (D) SEM observation images of Mixed Siliceous Shale Lithofacies (S-2); (E) & (F) SEM observation images of Calcareous/Siliceous Mixed Shale Lithofacies (M-1); (G) & (H) SEM observation images of Argillaceous/Siliceous Mixed Shale Lithofacies (M-2); (I) & (J) SEM observation images of Mixed Calcareous Shale Lithofacies (C-2); (K) & (L) SEM observation images of Argillaceous-Bearing Calcareous Shale Lithofacies (C-3).

4.3.2 Inorganic pore

Inorganic pores in the basin facies shale are predominantly composed of intragranular dissolution pores supported by rigid minerals (Figures 7A–D). The lower slope facies shale exhibit more developed inorganic pores, primarily including clay mineral interlayer pores, intergranular pores, intragranular pores, and partial pyrite intercrystalline pores. Their diameters vary significantly, ranging from tens of nanometers to several micrometers, with the largest extending into micron-scale fracture pores. Intergranular pores are mainly distributed along the edges of quartz and calcite grains, exhibiting triangular or irregular polygonal shapes. Intragranular pores, typically sub-circular, elliptical, or irregular polygonal in form, occur within quartz and carbonate minerals (Figures 7E–H). In the shale of upper slope facies, inorganic pores are dominated by dissolution-derived pores intersecting with clay/pyrite pores, forming interconnected networks (Figures 7I–L). Additionally, discordant contacts between inorganic minerals and clay mineral edges, influenced by matrix-mineral interfacial relationships, create slit-shaped pores or fractures with widths ranging from tens to hundreds of nanometers.

Figure 7

Figure 7. Images showing inorganic pore (yellow and blue arrows represent clay minerals and other inorganic minerals related pore, respectively) in the shale samples of Well (A) Well (B) and Well (C). (A) & (B) SEM observation images of Calcareous Siliceous Shale Lithofacies (S-1); (C) & (D) SEM observation images of Mixed Siliceous Shale Lithofacies (S-2); (E) & (F) SEM observation images of Calcareous/Siliceous Mixed Shale Lithofacies (M-1); (G) & (H) SEM observation images of Argillaceous/Siliceous Mixed Shale Lithofacies (M-2); (I) & (J) SEM observation images of Mixed Calcareous Shale Lithofacies (C-2); (K) & (L) SEM observation images of Argillaceous-Bearing Calcareous Shale Lithofacies (C-3).

4.3.3 Microfracture

Microfractures in basin and lower slope facies shales are primarily distributed along mineral edges and within mineral grains. Most microfractures exhibit favorable extensibility, with lengths reaching tens of micrometers and widths ranging from tens to hundreds of nanometers. Edge microfractures, predominantly diagenetic shrinkage fractures, form at the boundaries of clay and inorganic minerals. Intragranular fractures, caused by stress release during tectonic activity, penetrate mineral grains, extending for several to tens of micrometers, thereby enhancing pore connectivity (Figures 8A–H). Microfractures in upper slope facies shales are more extensively developed, primarily generated by overpressure from hydrocarbon generation and tectonic stresses. These microfractures display parallel alignment or mutual intersection. Microfractures widths can exceed 1 μm, and lengths may span tens to hundreds of micrometers (Figures 8I–L).

Figure 8

Figure 8. Ternary Images showing microfracture (green arrows) in the shale samples of Well (A) Well (B) and Well (C). (A) & (B) SEM observation images of Calcareous Siliceous Shale Lithofacies (S-1); (C) & (D) SEM observation images of Mixed Siliceous Shale Lithofacies (S-2); (E) & (F) SEM observation images of Calcareous/Siliceous Mixed Shale Lithofacies (M-1); (G) & (H) SEM observation images of Argillaceous/Siliceous Mixed Shale Lithofacies (M-2); (I) & (J) SEM observation images of Mixed Calcareous Shale Lithofacies (C-2); (K) & (L) SEM observation images of Argillaceous-Bearing Calcareous Shale Lithofacies (C-3).

4.4 Gas content

4.4.1 Methane isothermal adsorption gas content

Isothermal methane adsorption experiments were conducted under formation temperature conditions corresponding to different samples, yielding adsorption capacities under varying pressure conditions. The Langmuir model (Equation 6.1) was subsequently applied to obtain the methane saturated adsorption gas content (V_L) under formation conditions. The shale association of upper slope facies displayed the lowest methane saturation adsorption capacity (V_L), ranging from 0.60 m³/t to 1.49 m³/t with an average of 1.07 m³/t. The lower slope facies shale association showed intermediate values, with Langmuir adsorption content (V_L) values ranging from 1.01 m³/t to 3.67 m³/t and averaging 2.19 m³/t. In contrast, the shale association of basin facies exhibited the highest methane adsorption capacity, demonstrating V_L values between 2.23 m³/t and 3.63 m³/t, with a mean value of 2.90 m³/t (Table 1).

4.4.2 Field measured gas content

The gas content of basin facies shale association ranges from 0.04 m³/t to 0.14 m³/t, representing the lowest values among the three sedimentary facies analyzed. In contrast, shale association of upper slope facies exhibit significantly higher gas concentrations, with measured values spanning 0.51 m³/t to 2.58 m³/t and a mean value of 1.16 m³/t. Comparatively, lower slope facies shale association demonstrate the most substantial gas storage capacity, displaying a gas content range of 0.34 m³/t to 2.62 m³/t and achieving the highest average value of 1.40 m³/t (Table 1).

4.4.3 Theoretical gas content

The adsorbed gas content ($V_{ads}$) and the standard-state free gas content ($V_{free}$) for 14 shale samples were quantitatively evaluated, with detailed results presented in Table 2. Basin facies shale association exhibit the highest theoretical gas content (2.90 m³/t avg.), with adsorbed gas dominating at 1.98 m³/t (68.28%) and free gas contributing 0.92 m³/t (31.72%), but near-zero measured values. The lower slope facies shale association show moderate theoretical gas content (1.81 m³/t avg.) with the highest measured gas content. It remains predominantly adsorbed gas-rich, containing 1.67 m³/t adsorbed gas (66.80%) and 0.83 m³/t free gas (33.20%). Shale association of upper slope facies shale exhibits the lowest theoretical values (1.70 m³/t avg.) while showing intermediate measured contents. Obviously, there is a clear discrepancy between the theoretical gas content and the actual measured values. The lower slope facies shale association, characterized by moderate hydrocarbon generation capacity and reservoir properties, paradoxically exhibits the highest measured gas content. In contrast, the basin facies shale association, despite demonstrating optimal hydrocarbon-generating potential and superior reservoir performance, shows not only significantly lower measured gas content than the lower slope facies but also falls below that of the upper slope facies.

Table 2

Table 2. Statistics of adsorbed gas content, free gas content and total gas content in different sedimentary facies.

5 Discussion

5.1 Difference of “source-reservoir-seal” system

5.1.1 Shale association of basin facies

The basin facies shale association predominantly consists of continuous thick-bedded siliceous mudstone (S-1 and S-2) characterized by the complete absence of argillaceous limestone interbeds. Despite demonstrating superior source-reservoir quality parameters compared to other shale associations, it paradoxically exhibits the lowest gas content. A systematic analysis of high-quality shale interval in Well A (1919m–1940 m; Figure 9) reveals distinctive shale gas accumulation patterns, providing critical insights into the gas-bearing mechanisms of high-quality shale reservoirs but low-gas-content. The extremely low carbonate mineral content in these shale formations is a key contributor to their reduced triaxial stress strength. Under multi-phase tectonics stresses, progressive fracturing initiates at microscopic scales when external stresses surpass rock strength under confining pressure conditions (Gale et al., 2022; Li et al., 2025; Wang et al., 2025). This fracturing process systematically upscales to macroscopic dimensions, generating extensive high-angle fractures and causing structural disintegration of shale units (Figure 9). In addition, the absence of argillaceous limestone interlayers critically compromises the formation of effective upper seals. Consequently, the combined structural and seal failures create interconnected gas migration pathways, ultimately leading to gas escape.

Figure 9

Figure 9. The “source-reservoer-seal” system of basin facies shale association.

5.1.2 Shale association of lower slope facies

The lower slope facies shale association comprises calcareous mudstones dominated by M-1 and M-2 lithofacies, which is interbedded with argillaceous limestone layers primarily composed of C-2 lithofacies. Well B is selected as a representative lower slope facies example, with detailed analysis focused on the interval (1,537m–1555 m) where peak gas logging responses were recorded (Figure 10).

Figure 10

Figure 10. The “source-reservoer-seal” system of lower slope facies shale association.

The interval below 1548 m exhibits distinct fracture development characteristics, dominated by bedding-parallel fractures, horizontal fractures, and low-angle intrastratal fractures (Figure 10). This interval demonstrates significant gas-bearing potential, with gas logging values exceeding 30% and a vertical gas anomaly spanning approximately 5 m (Figure 10). The maximum on-site measured gas content of 1.63 m³/t confirms this unit as a high gas-bearing layer. With increasing depth shallowing upward, the lithology gradually transitions to argillaceous limestone, accompanied by a progressive increase in carbonate mineral content and a concurrent decrease in clay minerals. This mineralogical evolution creates a pronounced brittleness contrast between lithologies (He et al., 2024; Wang et al., 2025). Higher clay content and lower carbonate content can enhance ductility, showing significant negative correlation with triaxial stress strength (Sone and Zoback, 2013; Rybacki et al., 2015; Herrmann et al., 2018). Evidently, the clay minerals of shale predominantly act as ductile components, displaying a significant negative correlation with triaxial stress strength, thereby impeding stress resistance enhancement (Rybacki et al., 2015; Herrmann et al., 2018). In contrast, carbonate mineral content exhibits a strong positive correlation with shale triaxial stress strength, while siliceous mineral content shows no statistically significant relationship (Sone and Zoback, 2013; Herrmann et al., 2018; Zou, et al., 2023). This disparity arises from the superior mechanical strength of carbonate minerals significantly enhances bulk shale stress resistance (Gao et al., 2017; He et al., 2024).

At the lithological transition boundary (1,547.8 m), sporadic high-angle fractures (<0.1 m in length) interconnect with bedding-parallel fractures, forming a complex fracture network within 2–3 m vertical range. This structural heterogeneity enhances gas migration efficiency by through improved fracture connectivity (Zhao et al., 2017a; Zhu, et al., 2019; Chen, et al., 2022). Micron-scale fractures (5–20 μm) and dissolution pores in inorganic minerals synergize with nanopore networks, expanding effective flow areas and enhancing localized storage capacity (Qiao et al., 2020; Wu et al., 2023). Notably, 20–30 cm thick gas-bearing intervals persist in transition-adjacent argillaceous limestone, demonstrating persistent hydrocarbon accumulation potential under such petrophysical conditions.

With further upward shallowing of depth, the carbonate mineral content progressively increases while clay mineral content diminishes, leading to enhanced triaxial stress strength within the shale that exceeds external stress intensity (Sone and Zoback, 2013; Rybacki et al., 2015; Yang et al., 2025b). This results in a highly compacted lithology with minimal fracture development, effectively ceasing deformation and maintaining structural stability (Zhu et al., 2025; Yang et al., 2025b). These mechanical properties establish a direct caprock that effectively seals the underlying gas-bearing layers. In addition, the sealing system is further enhanced by the underlying Devonian Wuzhishan Formation. This formation predominantly consists of micritic-siliceous limestones with regional thicknesses of 80–120 m and permeability below 0.01 mD (Mei et al., 2007; Huang et al., 2013; Mei et al., 2013), functioning as an effective basal seal that significantly inhibits vertical migration.

5.1.3 Shale association of upper slope facies

The upper slope facies shale association is predominantly composed of calcareous mudstone dominated by the C-3 lithofacies, interbedded with argillaceous limestone layers primarily consisting of the C-2 lithofacies. Compared to the lower slope facies, this shale association contains a higher frequency and greater cumulative thickness of interbeds. Taking the well C in the upper slope facies as a representative example, the 1,679m–1688 m interval with elevated gas logging values was selected to systematically analyze the shale gas accumulation patterns (Figure 11).

Figure 11

Figure 11. The “source-reservoer-seal” system of upper slope facies shale association.

The upper slope facies shale association exhibits vertically continuous calcareous mudstone units compartmentalized by interbedded argillaceous limestone layers, resulting in enhanced lithological heterogeneity. Within this configuration, the basal calcareous mudstone functions as the primary gas source, where organic matter preferentially fills microfractures in banded distribution patterns (Figures 6I,K). Intermediate argillaceous limestone interlayers demonstrate effective connectivity of dissolution pores and microfractures near lithofacies transition zones (Figures 8I–L), forming favorable reservoir intervals. Conversely, distal interlayer segments develop competent caprocks that effectively seal underlying reservoirs. The overlying calcareous mudstone above these interlayers lacks direct caprock confinement, resulting in negligible gas logging anomalies and significantly reduced measured gas content (Figure 11).

Notable differences exist in “source-reservoir-seal” configurations between upper and lower slope facies association. The calcareous mudstone of upper slope facies (predominantly comprising C-3 lithofacies) demonstrates constrained hydrocarbon potential due to its reduced thickness (typically <5 m), lower TOC content (averaging 0.99 wt%), and limited adsorption capacity (averaging V_L = 1.07 m³/t). These constraints produce narrow gas-bearing interval with gas logging anomalies spanning approximately 2 m (Figure 11), substantially less pronounced than lower slope facies counterparts. Furthermore, thickened argillaceous limestone interlayers (3m–5 m vs. 1m–2 m in lower slope facies) enhance sealing capacity through increased caprock thickness, as evidenced by formation pressure coefficients reaching 1.18 (over pressured conditions) in Well C. The over pressured system promotes efficient gas accumulation along lithofacies transition zones, resulting in pronounced gas logging anomalies characterized by rapid amplitude increases during drilling penetration.

5.2 Shale gas accumulation pattern

Through systematic analysis of shale association across sedimentary facies in the Yaziluo Rift Troughs, it can be inferred that vertical sequence configurations under distinct sedimentary settings fundamentally control the “source-reservoir-seal” configurations within shale associations. The basin facies shale association, characterized by high TOC (1.46–5.70wt%) thick-bedded siliceous mudstone with low triaxial compressive strength, demonstrates intensive high-angle fractures (averaging density 12.5 fractures/m) causing shale fragmentation. The gas occurrence pattern predominantly features adsorbed gas (68.28% of total), with limited free gas (31.72% of total) due to inadequate migration pathways and storage space. The poorly configured “source-reservoir-seal” configurations within this shale association significantly reduces gas retention efficiency, ultimately resulting in extremely low measured gas content values (Figure 12). It essentially reflects the critical influence of the “source-reservoir-seal” configurations on shale gas accumulation effectiveness in the Yaziluo Rift Troughs.

Figure 12

Figure 12. The accumulation patterns of shale gas in different sedimentary facies shale association (A) and variation trend of shale gas content (B).

The lower slope facies shale association demonstrates moderate organic matter abundance (0.86–3.51 wt%), with pore systems dominated by organic-clay composite structures. Argillaceous limestone interlayers contrastingly develop brittle mineral-associated pore, comprising intergranular pores, intragranular dissolution features, and microfracture networks. Due to vertical variations in the sequence shale association, the argillaceous limestone interlayers compartmentalize the continuously developed calcareous mudstone into upper and lower sections, serving as direct caprocks to effectively seal the underlying calcareous mudstone. The lower shale unit functions as the primary gas source, driving upward hydrocarbon migration. Lithological transition zones exhibit enhanced connectivity through interconnected fracture systems, forming high-quality pore-fracture reservoirs. This optimized “source-reservoir-seal” configurations provides enhanced percolation pathways and expanded storage spaces for free gas, resulting in significant shale gas accumulation at lithological transitions where gas logging values reach their maximum (Figure 12). Conversely, the upper shale gas-bearing interval exhibits inferior gas retention conditions due to lacking direct caprock sealing.

Within the shale association of the upper slope facies, calcareous mudstone and argillaceous limestone exhibit frequent interbedding, forming a rhythmic alternation of carbonate-rich and argillaceous-dominated lithologies. Characterized by relatively high carbonate content (51.4%–63.7%) and the low organic matter abundance (1.5% avg.), its pore system is dominated by clay mineral-related pore, particularly clay mineral interlayer pores and organic-clay composite pores. Multiple sets of argillaceous limestone interbeds vertically compartmentalize the continuously calcareous mudstone into several well-defined self-sealing systems. Furthermore, the intricate pore-fracture network, comprising abundant inorganic pores and microfractures, facilitates enhanced free gas migration and multi-point accumulation (Figure 12). However, the vertical gas-bearing intervals remains limited due to inherent shale quality limitations.

6 Conclusion

Through systematic analysis of geological characteristics and gas-bearing properties for the lower Carboniferous shale in the Yaziluo Rift Trough, shale gas accumulation pattern have been established with particular emphasis on the synergistic effects between lithofacies heterogeneity and “source-reservoir-seal” configurations.

1. Lower slope facies shale association. It represents the most favorable exploration target, characterized by an integrated “source-reservoir-seal” configurations that ensures effective shale gas accumulation and retention. At lithological transitions, interconnected inorganic pores and microfractures create high-quality reservoirs. Gas migrates upward from source rocks and accumulates preferentially in these transition zones, achieving high gas content.

2. Upper slope facies shale association. Its spatially heterogeneous architecture, marked by frequent mudstone-limestone interbedding, creates multiple vertically stacked self-contained compartments. Its unique “source-reservoir-seal” configurations ensures effective gas accumulation despite suboptimal shale quality, resulting secondary gas-bearing potential with measured gas content second only to the lower slope facies.

3. Basin facies shale association. While it is characterized by thick continuous shale with the high TOC values, suffers from a clay-dominated composition prone to brittle failure under external stress. Critically, the absence of interbedded argillaceous limestone layers results in ineffective vertical confinement, allowing shale gas escape. Consequently, it exhibits negligible gas retention capacity, as evidenced by extremely low gas content.

Data availability statement

The original contributions presented in the study are included in the article/supplementary material, further inquiries can be directed to the corresponding authors.

Author contributions

XC: Writing – original draft, Writing – review and editing. DS: Funding acquisition, Project administration, Writing – review editing. RC: Writing – review and editing, Funding acquisition, Resources. FL: Writing – review and editing. XY: Methodology, Writing – review and editing. WC: Resources, Writing – review and editing. YW: Formal Analysis, Writing – review and editing. XX: Writing – review and editing.

Funding

The author(s) declared that financial support was received for this work and/or its publication. This study was jointly funded by the National Natural Science Foundation of China (Grant No. U24A20601), the China Geological Survey Project of “Investigation and evaluation of shale gas resources in Ninglang Basin” (DD20242219), and the Guangxi Geological Survey Project of” Geological conditions and resource evaluation of Carboniferous shale gas in northern Guizhong Depression” ([2021]3421No. (001-012)).

Conflict of interest

Author XY was employed by Petroleum Exploration and Production Research Institute, SINOPEC.

The remaining author(s) declared that this work was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

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